Processing exhaust for use in enhanced oil recovery

ABSTRACT

A method for generating steam for hydrocarbon production is provided. The method includes producing steam using heat from an exhaust stream from a gas turbine system. A water stream is condensed from combustion products in the exhaust stream, and the water stream is used as a make-up water for production of the steam.

CROSS REFERENCE TO RELATED APPLICATIONS

This application claims the priority benefit of U.S. Patent Application61/775,167 filed Mar. 8, 2013 entitled PROCESSING EXHAUST FOR USE INENHANCED OIL RECOVERY, the entirety of which is incorporated byreference herein.

FIELD

Exemplary embodiments of the present techniques relate to techniques forrecovering exhaust heat from a combined cycle plant and using therecovered exhaust heat for enhanced oil recovery.

BACKGROUND

This section is intended to introduce various aspects of the art, whichmay be associated with exemplary embodiments of the present techniques.This discussion is believed to assist in providing a framework tofacilitate a better understanding of particular aspects of the presenttechniques. Accordingly, it should be understood that this sectionshould be read in this light, and not necessarily as admissions of priorart.

A Brayton cycle engine commonly known as a gas turbine can be adapted tocombust fuel at near stoichiometric conditions with exhaust gasrecirculation. Such an engine is referred to as an ultra-low emissiontechnology (ULET) because the emissions produced by the engine areprimarily inert gases with low contaminant contents. Some ULET enginesuse the exhaust heat of the gas turbine to produce multiple pressurelevels of superheated steam that is used in a condensing steam turbineto produce additional shaft power. In PCT Application Publication No.WO2012003079, such an arrangement is described and referred to ascombined cycle power generation (CCPG). A power plant that implementsCCPG is referred to as a combined cycle power plant or, simply, acombined cycle plant. Gas turbine combined cycle plants are ratherefficient and can be operated at relatively low cost when compared toother technologies, such as coal and nuclear.

The steam turbine in a combined cycle plant runs most efficiently withhigh quality, i.e., dry, steam. Production of dry steam requires a waterfeed that is substantially free of contaminants, such as minerals,salts, and silica. Although water is produced as a byproduct of thecombustion process in a ULET engine, this water is of low quality and istherefore not readily usable by a boiler of the steam turbine. The costof purifying the water is often prohibitive and, therefore, the water isoften simply discarded. Moreover, although the steam turbine in acombined cycle plant produces blowdown water, this water is also of lowquality and is, therefore, discarded in many instances.

In addition, although using the exhaust heat of the gas turbine toproduce additional shaft power instead of merely venting it improvesoverall efficiency of the combined cycle plant, there may be moreeconomical uses for the exhaust heat. However, current combined cycleplants are not equipped to use the exhaust heat or the steam producedwith the exhaust heat for any alternative purposes.

For example, U.S. Pat. No. 4,271,664 to Earnest discloses a turbineengine with exhaust gas recirculation. The engine has a main powerturbine operating on an open-loop Brayton cycle. The air supply to themain power turbine is furnished by a compressor independently driven bythe turbine of a closed-loop Rankine cycle which derives heat energyfrom the exhaust of the Brayton turbine. A portion of the exhaust gas isrecirculated into the compressor inlet during part-load operation.However, no additional uses are disclosed for the exhaust heat or thesteam produced with the exhaust heat.

SUMMARY

An embodiment described herein provides a method for generating steamfor hydrocarbon production using a combined cycle power plant. Themethod includes producing steam using heat from an exhaust stream from agas turbine system, condensing a water stream from combustion productsin the exhaust stream, and using the water stream as a make-up water forproduction of the steam.

Another embodiment provides a method for using exhaust from a combinedcycle plant in hydrocarbon production. The method includes producingsteam using exhaust heat from an exhaust stream from a gas turbinesystem in the combined cycle plant and condensing a water stream fromthe exhaust stream. The water stream is used as a make-up stream for thesteam production. A steam turbine is driven with at least a portion ofthe steam and at least another portion of the steam is injected into ahydrocarbon reservoir for a thermal recovery process.

Another embodiment provides a system for generating power and thermallyrecovering hydrocarbons from a reservoir. The system includes a gasturbine system configured to produce a hot exhaust stream as a byproductof combustion. The system also includes a heat recovery steam generator(HRSG) configured to produce a steam stream using the hot exhauststream, wherein the HRSG produces a condensate stream from thecombustion products in the hot exhaust stream. A feed system isconfigured to use the condensate stream as at least part of a make-upwater provided to the HRSG to generate the steam stream.

BRIEF DESCRIPTION OF THE DRAWINGS

The advantages of the present techniques are better understood byreferring to the following detailed description and the attacheddrawings, in which:

FIG. 1 is a schematic of a development illustrating the use of thermalrecovery systems with a steam producing cogeneration facility;

FIG. 2 is a simplified block diagram of another development illustratinga detailed view of a cogeneration facility of the development;

FIG. 3 is a simplified block diagram of another development illustratinga detailed view of a cogeneration facility of the development;

FIG. 4 is a simplified block diagram of a portion of the development ofFIG. 3 illustrating a detailed view of the HRSG of the developmentaccording to a first embodiment;

FIG. 5 is a simplified block diagram of a portion of the development ofFIG. 3 illustrating a detailed view of the HRSG of the developmentaccording to a second embodiment;

FIG. 6 is a process flow diagram of a method for using exhaust heat in acombined cycle plant; and

FIG. 7 is a process flow diagram of another method for using exhaustheat in a combined cycle plant.

DETAILED DESCRIPTION

In the following detailed description section, specific embodiments ofthe present techniques are described. However, to the extent that thefollowing description is specific to a particular embodiment or aparticular use of the present techniques, this is intended to be forexemplary purposes only and simply provides a description of theexemplary embodiments. Accordingly, the techniques are not limited tothe specific embodiments described below, but rather, include allalternatives, modifications, and equivalents falling within the truespirit and scope of the appended claims.

At the outset, for ease of reference, certain terms used in thisapplication and their meanings as used in this context are set forth. Tothe extent a term used herein is not defined below, it should be giventhe broadest definition persons in the pertinent art have given thatterm as reflected in at least one printed publication or issued patent.Further, the present techniques are not limited by the usage of theterms shown below, as all equivalents, synonyms, new developments, andterms or techniques that serve the same or a similar purpose areconsidered to be within the scope of the present claims.

“Bitumen” is a naturally occurring heavy oil material. It is often thehydrocarbon component found in oil sands. Bitumen can vary incomposition depending upon the degree of loss of more volatilecomponents. It can vary from a very viscous, tar-like, semi-solidmaterial to solid forms. The hydrocarbon types found in bitumen caninclude aliphatics, aromatics, resins, and asphaltenes. A typicalbitumen might be composed of:

-   -   19 weight percent (wt. %) aliphatics, which can range from 5 wt.        %-30 wt. %, or higher;    -   19 wt. % asphaltenes, which can range from 5 wt. %-30 wt. %, or        higher;    -   30 wt. % aromatics, which can range from 15 wt. %-50 wt. %, or        higher;    -   32 wt. % resins, which can range from 15 wt. %-50 wt. %, or        higher; and    -   some amount of sulfur, which can range in excess of 7 wt. %.        In addition bitumen can contain some water and nitrogen        compounds ranging from less than 0.4 wt. % to in excess of 0.7        wt. %. The metals content, while small, can be removed to avoid        contamination of the product synthetic crude oil (SCO). Nickel        can vary from less than 75 ppm (part per million) to more than        200 ppm. Vanadium can range from less than 200 ppm to more than        500 ppm. The percentage of the hydrocarbon types found in        bitumen can vary.

The “Clark hot water extraction process” or “CHWE” was originallydeveloped for releasing bitumen from oil sands, based on the work of Dr.K. A. Clark, and discussed in a paper by Corti et al., “AthabascaMineable Oil Sands: The RTR/Gulf Extraction Process Theoretical Model ofBitumen Detachment,” The 4th UNITAR/UNDP International Conference onHeavy Crude and Tar Sands Proceedings, vol. 5, Edmonton, AB, Aug. 7-12,1988, pp. 41-44, 71. The process, which is also described in U.S. Pat.No. 4,946,597, uses vigorous mechanical agitation of oil sands withwater and caustic alkali to disrupt the granules and form a slurry,after which the slurry is passed to a separation tank for the flotationof the bitumen, from which the bitumen is skimmed. The process may beoperated at ambient temperatures, with a conditioning agent being addedto the slurry. Earlier methods used temperatures of 85° C. and abovetogether with vigorous mechanical agitation and are highly energyinefficient. Chemical adjuvants, particularly alkalis, have beenutilized to assist these processes.

A “combined cycle power plant” or “CCPP” (also referred to herein as a“combined cycle plant”) includes a gas turbine, a steam turbine, agenerator, and a heat recovery steam generator (HRSG), and uses bothsteam and gas turbines to generate power. The gas turbine operates in anopen or semi-closed Brayton cycle, and the steam turbine operates in aRankine cycle. Combined cycle power plants utilize heat from the gasturbine exhaust to boil water in the HRSG to generate steam. The steamgenerated is utilized to power the steam turbine. After powering thesteam turbine, the steam may be condensed and the resulting waterreturned to the HRSG. The gas turbine and the steam turbine can beutilized to separately power independent generators, or in thealternative, the steam turbine can be combined with the gas turbine tojointly drive a single generator via a common drive shaft. Thesecombined cycle gas/steam power plants generally have higher energyconversion efficiency than Rankine-cycle or steam-only power plants.Currently, simple-cycle plant efficiency can exceed 44% while combinedcycle plant efficiency can exceed 60%. The higher combined cycleefficiencies result from synergistic utilization of a combination of thegas turbine with the steam turbine.

A “compressor” is a machine that increases the pressure of a gas by theapplication of work (i.e., compression). Accordingly, a low pressure gas(e.g., at about 35 kPa) may be compressed into a high-pressure gas(e.g., at about 6,895 kPa) for transmission through a pipeline,injection into a well, or other processes.

As used herein, “condensate” includes liquid water formed by thecondensation of steam. Steam may also entrain liquid water, in the formof water droplets. This entrained water may also be termed condensate,as it may arise from condensation of the steam, although the entrainedwater droplets may also originate from the incomplete conversion ofliquid water to steam in a boiler.

“Cyclic Steam Stimulation” of “CSS” (also known as the “huff-and-puff”process) refers to a hot in-situ mining process in which a well is putthrough cycles of steam injection, heat soak, and pumped oil production.Specifically, CSS involves the cyclic introduction of high-temperature(e.g., about 300° C.-400° C.) steam into a reservoir through ahorizontal well for prolonged periods of time (e.g., weeks to months).This may allow the steam to heat the mineralized formation and tofluidify the oils. The oils can then be recovered at the surface. Theproduction and, therefore, the recovery of the oils may take placethrough another horizontal well situated at a higher depth.

A “dehydration device” is a device for removing water, in gaseous orliquid form, from a gas mixture. “Dewatered” describes broadly anyreduction of water content. Typically, a dewateredhydrocarbon-containing material can have a majority of the water contentsubstantially removed, e.g., less than about 5% by volume water or lessthan about 1% depending on the particular material and starting watercontent. Water contents much less than 1% may be desirable for certaingas streams.

A “development” is a project for the recovery of hydrocarbons usingintegrated surface facilities and long term planning. The developmentcan be directed to a single hydrocarbon reservoir, although multipleproximate reservoirs may be included.

“Enriched” as applied to any stream withdrawn from a process means thatthe withdrawn stream contains a concentration of a particular componentthat is higher than the concentration of that component in the feedstream to the process.

As used herein, “exemplary” means “serving as an example, instance, orillustration.” Any embodiment described herein as “exemplary” is not tobe construed as preferred or advantageous over other embodiments.

A “facility” is a representation of a tangible piece of physicalequipment through which hydrocarbon fluids are either produced from areservoir or injected into a reservoir. In its broadest sense, the termfacility is applied to any equipment that may be present along the flowpath between a reservoir and its delivery outlets, which are thelocations at which hydrocarbon fluids either enter the reservoir(injected fluids) or leave the reservoir (produced fluids). Facilitiesmay include production wells, injection wells, well tubulars, wellheadequipment, gathering lines, manifolds, pumps, compressors, separators,surface flow lines, and delivery outlets. As used herein, a facility mayalso include a gas treatment unit, such as an acid gas separation unit,a cryogenic separation system, or a dehydration unit. In some instances,the term “surface facility” is used to distinguish those facilitiesother than wells. A “facility network” is the complete collection offacilities that are present in the system, which would include all wellsand the surface facilities between the wellheads and the deliveryoutlets.

The term “gas” is used interchangeably with “vapor,” and means asubstance or mixture of substances in the gaseous state as distinguishedfrom the liquid or solid state. Likewise, the term “liquid” means asubstance or mixture of substances in the liquid state as distinguishedfrom the gas or solid state.

A “heat recovery steam generator” or “HRSG” is a heat exchanger orboiler that recovers heat from a hot gas stream. It produces steam thatcan be used in a process or used to drive a steam turbine. A commonapplication for an HRSG is in a combined-cycle power plant, where hotexhaust from a gas turbine is fed to the HRSG to generate steam which inturn drives a steam turbine. As described herein, the HRSG may be usedto provide steam to an enhanced oil recovery process, such as CSS orSAGD.

“Heavy oil” includes oils which are classified by the American PetroleumInstitute (API) as heavy oils or extra heavy oils. In general, a heavyoil has an API gravity between 22.3° (density of 920 kg/m³ or 0.920g/cm³) and 10.0° (density of 1,000 kg/m³ or 1 g/cm³). An extra heavyoil, in general, has an API gravity of less than 10.0° (density greaterthan 1,000 kg/m³ or greater than 1 g/cm³). For example, a source ofheavy oil includes oil sand or bituminous sand, which is a combinationof clay, sand, water, and bitumen. The thermal recovery of heavy oils isbased on the viscosity decrease of fluids with increasing temperature orsolvent concentration. Once the viscosity is reduced, the mobilizationof fluids by steam, hot water flooding, or gravity is possible. Thereduced viscosity makes the drainage quicker and therefore directlycontributes to the recovery rate.

A “hydrocarbon” is an organic compound that primarily includes theelements hydrogen and carbon, although nitrogen, sulfur, oxygen, metals,or any number of other elements may be present in small amounts. As usedherein, hydrocarbons generally refer to organic materials that areharvested from hydrocarbon containing sub-surface rock layers, termedreservoirs. For example, natural gas, oil, and coal are hydrocarbons.

“Hydrocarbon production” or “production” refers to any activityassociated with extracting hydrocarbons from a well or other opening.Hydrocarbon production normally refers to any activity conducted in oron the well after the well is completed. Accordingly, hydrocarbonproduction or extraction includes not only primary hydrocarbonextraction but also secondary and tertiary production techniques, suchas injection of gas or liquid for increasing drive pressure, mobilizingthe hydrocarbon or treating by, for example, chemicals or hydraulicfracturing the well bore to promote increased flow, well servicing, welllogging, and other well and wellbore treatments.

The term “natural gas” refers to a gas obtained from a crude oil well(associated gas), from a subterranean gas-bearing formation(non-associated gas), or from a coal bed. The composition and pressureof natural gas can vary significantly. A typical natural gas streamcontains methane (CH₄) as a significant component. Raw natural gas mayalso contain ethane (C₂H₆), higher molecular weight hydrocarbons, acidgases (such as carbon dioxide, hydrogen sulfide, carbonyl sulfide,carbon disulfide, and mercaptans), and contaminants such as water,nitrogen, iron sulfide, wax, and crude oil.

“Pressure” is the force exerted per unit area by the gas on the walls ofthe volume. Pressure can be shown as kilopascals (kPa).

As used herein, a “Rankine cycle power plant” includes a vaporgenerator, a turbine, a condenser, and a recirculation pump. For examplewhen the vapor is steam, a “Rankine cycle power plant” includes a steamgenerator, a steam turbine, a steam condenser, and a boiler feed waterpump. The steam is used to generate electricity by driving a generatorfrom the steam turbine. The reduced pressure steam is then condensed inthe steam condenser. The resulting water is recirculated to the steamgenerator to complete the loop.

“Reservoir formations” or “reservoirs” are typically pay zones includingsandstone, limestone, chalk, coal, and some types of shale. Pay zonescan vary in thickness from less than one foot (0.3048 meters) tohundreds of feet (hundreds of meters). The permeability of the reservoirformation provides the potential for production.

“Sequestration” refers to the storing of a gas or fluid that is aby-product of a process rather than discharging the fluid to theatmosphere or open environment. For example, as described herein, carbondioxide gas formed from the burning or steam reforming of hydrocarbonsmay be sequestered in underground formations, such as coal beds.

“Steam Assisted Gravity Drainage” or “SAGD” is a thermal recoveryprocess in which steam is injected into a first well to lower aviscosity of a heavy oil, and fluids are recovered from a second well.Both wells are usually horizontal in the formation, and the first welllies above the second well. Accordingly, the reduced viscosity heavy oilflows down to the second well under the force of gravity, althoughpressure differential may provide some driving force in variousapplications.

The term “steam-flooding” is synonymous with the term “steam injection.”Both terms describe a technique by which steam is injected into anunderground formation to cause increased flow of viscous hydrocarbons.

As used herein, a “steam generator” may include any number of devicesused to generate steam for a process facility, either directly or aspart of another process. Steam generators may include, for example, heatrecovery steam generators (HRSG), and once through steam generators(OTSG), among others. The steam may be generated at a number of qualitylevels. Steam quality is measured by the mass fraction of a cold waterstream that is converted into a vapor. For example, an 80% quality steamhas around 80 wt. % of the feed water converted to vapor. The steam isgenerated as wet steam that contains both steam vapor and associatedcondensate (or water). The wet steam may be passed through a separatorto generate a dry steam, i.e., without entrained condensate. As a resultof the separation, the separator also generates a liquid condensatestream.

As used herein, a “steam system” includes one or more steam generatorsrunning in parallel from a common feed water source and feeding steam toa common outlet. The steam system may include any number or types ofsteam generators in parallel. Often, the parallel steam generators ofthe steam system generate steam at a similar quality level.

“Substantial” when used in reference to a quantity or amount of amaterial, or a specific characteristic thereof, refers to an amount thatis sufficient to provide an effect that the material or characteristicwas intended to provide. The exact degree of deviation allowable may insome cases depend on the specific context.

As used herein, “thermal recovery processes” include any type ofhydrocarbon recovery process that uses a heat source to enhance therecovery, for example, by lowering the viscosity of a hydrocarbon. Theseprocesses may be based on heated water, wet steam, or dry steam, alone,or in any combinations. Further, any of these components may be combinedwith solvents to enhance the recovery. Such processes may includesubsurface processes, such as cyclic steam stimulation (CSS), steamflooding, and SAGD, among others, and processes that use surfaceprocessing for the recovery, such as sub-surface mining and surfacemining.

“Well” or “wellbore” refers to a hole in the subsurface made by drillingor insertion of a conduit into the subsurface. The terms areinterchangeable when referring to an opening in the formation. A wellmay have a substantially circular cross section, or othercross-sectional shapes. Wells may be cased, cased and cemented, oropen-hole well, and may be any type, including, but not limited to aproducing well, an injection well, an experimental well, and anexploratory well, or the like. A well may be vertical, horizontal, orany angle between vertical and horizontal (a deviated well), for examplea vertical well may include a non-vertical component.

Overview

Embodiments described herein extend combined cycle plant technologies toproduce steam for purposes other than generating additional shaft poweron a shaft of a gas turbine system in a combined cycle plant. Forexample, in various embodiments, a HRSG of the combined cycle plantproduces wet steam, i.e., steam with a quality equal to or less than 1,for use in a hydrocarbon thermal recovery process, such as a CSS processor a SAGD process. The hydrocarbons recovered by such processes aretypically viscous hydrocarbons, including heavy oil, tar, or bitumen.The HRSG may also produce dry steam for generation of additional shaftpower depending on the wet steam and power demands in the differentphases of a hydrocarbon recovery process. For example, the HRSG may bedesigned to convert 50% of the available exhaust heat to dry steam toprovide added power production for a nearby heavy oil upgrading, pumpingor compression facilities and convert the remaining exhaust heat toproduce wet steam for a thermal recovery process. Furthermore, the HRSGdesign may be flexible to control the steam flow from the dry steamsystem, for example by controlling the pressure of the steam drum and/orsteam coils, to affect the heat transfer balance between the dry and wetsteam systems. For example, by raising the dry steam pressure in thedrum and steam coils, less dry steam is boiled off due to the higherboiling temperature thus leaving more exhaust heat in the HRSG toproduce additional wet steam.

The HRSG cools the exhaust stream from the gas turbine engine in thecombined cycle power plant, which causes water formed in the combustionto condense out. Further cooling of the stream, for example in anexhaust gas recirculation system, can remove more water from the exhaustgas. The condensed water, or condensate, can be purified and used as asource of water for the steam production. As many hydrocarbon productionprocesses are located in areas with limited water resources, this canprovide an additional source of water for the processes.

A number of techniques have been developed for producing heavy oil fromsubsurface formations using thermal recovery operations. Thermalrecovery operations are used around the world to recover liquidhydrocarbons from both sandstone and carbonate reservoirs. Theseoperations include the conventional suite of steam based in-situ thermalrecovery techniques, such as CSS, steam-flooding, and SAGD, as well assurface mining and their associated thermal based surface extractiontechniques.

SAGD techniques are based on a continuous injection of steam through afirst well to lower the viscosity of heavy oils and a continuousproduction of the heavy oil from a lower-lying second well. In SAGD, twohorizontal wells are completed into the reservoir. The two wells arefirst drilled vertically to different depths within the reservoir.Thereafter, using directional drilling technology, the two wells areextended in the horizontal direction that result in two horizontalwells, vertically spaced from, but otherwise vertically aligned witheach other. Ideally, the production well is located above the base ofthe reservoir but as close as practical to the bottom of the reservoir,and the injection well is located vertically 10 to 30 feet (3 to 10meters) above the horizontal well used for production.

The upper horizontal well is utilized as an injection well and issupplied with steam from the surface. The steam rises from the injectionwell, permeating the reservoir to form a vapor chamber that grows overtime towards the top of the reservoir, thereby increasing thetemperature within the reservoir. The steam, and its condensate, raisethe temperature of the reservoir and consequently reduce the viscosityof the heavy oil in the reservoir. The heavy oil and condensed steamwill then drain downward through the reservoir under the action ofgravity and may flow into the lower production well, whereby theseliquids can be pumped to the surface. At the surface of the well, thecondensed steam and heavy oil are separated, and the heavy oil may bediluted with appropriate light hydrocarbons for transport by pipeline.

As a result of the unique wellbore configuration in SAGD, any condensateinjected into the reservoir with the steam will fall directly to theunderlying production well due to the influence of gravity, and therebynot contribute to the recovery of the hydrocarbons. For this reason, inSAGD projects such as those operating in the Athabasca region ofAlberta, the current convention is to separate the condensate and onlyinject the steam phase into the injection wells used in the recoveryprocess. The steam phase after the condensate has been removed iscommonly referred to as dry steam.

In various embodiments, the HRSG of the combined cycle plant includestwo steam generation systems, each being fed a different quality ofwater and producing a correspondingly different quality of steam. Forexample, a first stream of steam of low quality can be produced for usein hydrocarbon recovery process, while a second stream of high qualitysteam can be produced for use in generating additional shaft power in agas turbine system. The first and second streams of steam can beproduced simultaneously or, in some instances, only one stream can beproduced. The amount of steam produced in each stream can depend ondemand levels for hydrocarbon recovery and/or power generation. Inaddition, the condensed water produced as a byproduct of combustion inthe combined cycle plant and/or the blowdown water produced by the steamturbine of the combined cycle plant can be used as feed water forproducing low quality steam rather than simply being discarded.

Using Exhaust Heat from Combined Cycle Plant for Enhanced Oil Recovery

FIG. 1 is a schematic of a development 100 illustrating the use ofthermal recovery systems with a steam producing cogeneration facility.The thermal recovery systems that are illustrated include both a surfacemining 102 and extraction recovery process, and a subsurface thermalrecovery process 104, such as cyclic steam stimulation (CSS) or steamassisted gravity drainage (SAGD). The subsurface thermal recoveryprocess 104 allows for recovery of hydrocarbons from a reservoir 106that is too deep for surface mining. It will be clear that thetechniques described herein are not limited to this combination, orthese specific techniques, as any number of techniques or combinationsof techniques may be used in embodiments described herein. For example,the SAGD 104 recovery process can instead be a cyclic steam stimulation(CSS) recovery process or other thermal recovery process.

The surface mining 102 may be used to reach a portion of the reservoir106 that is closer to the surface, while the underground 104 recoverymay be used to access hydrocarbons in a portion of the reservoir 106that is at a greater depth. If, however, the reservoir does not have anyportion that is easily accessible by surface mining, the surface mining102 recovery process may be omitted.

In the development 100, a cogeneration facility 108 is used to generatepower and steam 110, which can be provided to a surface separationfacility 112 and an injection facility 114. The steam 110 may includewet steam only or both wet steam and dry stream, for example, carried indifferent pipes from the steam generation facility 108.

The surface mining 102 uses heavy equipment 116 to remove hydrocarboncontaining materials 118, such as oil sands, from the reservoir 106. Thehydrocarbon containing materials are offloaded at the separationfacility 112, where a thermal process, such as a Clark hot waterextraction (CHWE) process, among others, may be used to separate ahydrocarbon stream 120 from a tailings stream 122. The tailings stream122 may be sent to a tailings pond 124, or may be injected into asub-surface formation for disposal. A water stream 126 may be recycledto the steam generation facility 108. The extraction process may utilizewet steam from the cogeneration facility 108.

The subsurface thermal recovery process 104 injects the steam 110 intothe reservoir through injection wells 128 to produce hydrocarbons. Theinjection raises the temperature of a portion 130 of the reservoir 106to lower the viscosity of the hydrocarbons 131, allowing thehydrocarbons 131 to flow to collection wells 132. Although, for the sakeof clarity, the injection wells 128 and collection wells 132 are shownas originating from different locations in FIG. 1, these wells 128 and132 may be drilled from the same surface pads to enable easier trackingbetween the wells 128 and 132. Moreover, if the subsurface thermalrecovery process 104 is CSS, a single well may be used for both steaminjection and collection of hydrocarbons and steam condensate. Theresulting streams 134 from the reservoir 106 may include thehydrocarbons 131 and the condensate from the steam 110. The streams 134can be processed at a surface facility 136 to remove at least some ofthe water. A CSS process may use lower quality steam, e.g., greater thanabout 70%, while a SAGD process may utilize higher quality steam, e.g.,greater than about 90%, or dry steam from a steam generator at thecogeneration facility 108.

The hydrocarbon stream 138 and water stream 140 from the subsurfacethermal recovery process 104 may be sent to a transportation facility142, which may provide further separation and purification of theincoming streams 120, 138, and 140, prior to sending the marketablehydrocarbons 106 on to further processing facilities. The resultingprocess water 144 can be returned to a steam generator at thecogeneration facility 108 for recycling.

The schematic of FIG. 1 is not intended to indicate that the development100 is to include all the components shown in FIG. 1. Further, thedevelopment 100 may include any number of additional components notshown in FIG. 1, depending on the details of the specificimplementation.

FIG. 2 is a simplified block diagram of another development 200illustrating a detailed view of a cogeneration facility 202 of thedevelopment 200. The cogeneration facility 202 may correspond to thecogeneration facility 108 of FIG. 1. The cogeneration facility 202includes a gas turbine system 204, which may be characterized as apower-producing semi-closed Brayton cycle. In various embodiments, thegas turbine system 204 includes a combustion chamber (not shown) forcombusting a fuel 206 mixed with a compressed oxidant 208. The fuel 206may include any suitable hydrocarbon gas or liquid, such as natural gas,methane, ethane, naphtha, butane, propane, syngas, diesel, kerosene,aviation fuel, coal derived fuel, bio-fuel, oxygenated hydrocarbonfeedstock, or any combinations thereof. The oxidant 208 may include anysuitable gas containing oxygen, such as air, oxygen-rich air,oxygen-depleted air, pure oxygen, or any combinations thereof

In addition to a combustion chamber, the gas turbine system 204 includesa main compressor and an expander (not shown). The combustion chamber ofthe gas turbine system 204 produces an exhaust gas 210, which can besent to any variety of apparatuses and/or facilities in an exhaust gasrecirculation (EGR) system back to the gas turbine system 204. As theexhaust gas 210 expands through the expander of the gas turbine system204, it generates mechanical power to drive the main compressor of thegas turbine system 204 and an electrical generator 212, for example,through a shaft 214. Other systems may also be driven by the mechanicalpower, such as pumps, compressors, and/or other facilities.

In some implementations (not shown in FIG. 2), the EGR system mayinclude a compressor. As opposed to a conventional fan or blower system,the compressor can compress and increase the overall density of theexhaust gas, thereby directing a pressurized or compressed recycleexhaust gas 216 into the main compressor of the gas turbine system 204.The compressed recycle exhaust gas 216 can be used to help facilitate astoichiometric or substantially stoichiometric combustion of the oxidant208 and fuel 206 by moderating the temperature of the combustionproducts.

The EGR system of the cogeneration facility 202 includes a heat recoverysteam generator (HRSG) 218, or similar device. The HRSG 218 delivers afirst stream of steam 220 to a steam turbine 222. In variousembodiments, the combination of the HRSG 218 and the steam turbine 222are part of a power-producing closed Rankine cycle. The gaseous exhauststream 210 is introduced to the HRSG 218 and is used to generate thefirst stream of steam 220 and a recycled exhaust gas 216. The HRSG 218may optionally include a catalytic system to reduce residual oxygen,carbon monoxide, hydrogen, unburned hydrocarbons, or other products ofincomplete combustion in the exhaust gas 210.

In some embodiments, the first stream of steam 220 is sent to the steamturbine 222, as shown, to generate additional mechanical power. Theadditional mechanical power can be used to power a separate generator.Alternatively, the steam turbine 222 can be coupled, for example,through a gear box, to the shaft 214 of the gas turbine system 204 tosupplement the mechanical energy generated by the gas turbine system204. In some embodiments, the first stream of steam 220 is dry steam(i.e., high quality steam), which, relative to wet steam, reduces thelikelihood of scaling and associated damage on the inside of the steamturbine 222.

The HRSG 218 also delivers a second stream of steam 224 to a thermalrecovery system 226 to facilitate recovery of viscous hydrocarbons froma reservoir or from material removed from a reservoir. The thermalrecovery system 226 may implement a SAGD process, a steam-floodingprocess, a CSS process, a CHWE process, or the like. In someembodiments, the second stream of steam 224 is wet steam (i.e., lowquality steam), as shown. However, as will be explained in more detailbelow with reference to FIG. 4, the second stream of steam may insteadbe dry stream. The cogeneration facility 202 is not limited todelivering the second stream of steam 224 to a thermal recovery system226. In addition or alternatively, the cogeneration facility 202 maydeliver the second stream of steam 224, or a third stream of steam, to asystem that uses the stream of steam in a utility heating process, aprocess heating process, and/or a steam stripping process.

The block diagram of FIG. 2 is not intended to indicate that thedevelopment 200 is to include all the components shown in FIG. 2.Further, the development 200 may include any number of additionalcomponents not shown in FIG. 2, depending on the details of the specificimplementation. For example, the development 200 may include any numberof additional valves, gear boxes, sensors, control systems, condensers,or the like.

FIG. 3 is a simplified block diagram of another development 300illustrating a detailed view of a cogeneration facility 302 of thedevelopment 300. Certain elements in FIG. 3 have the same function ascorresponding elements in FIG. 2 and, accordingly, are referenced withthe same reference number as in FIG. 2. For example, the cogenerationfacility 302 of the development 300 includes the gas turbine system 204.The gas turbine system 204 can include a combustion chamber forcombusting the fuel 206 mixed with the compressed oxidant 208. Thecombustion chamber of the gas turbine system 204 produces exhaust gas210, which can be sent to any variety of apparatuses and/or facilitiesin an exhaust gas recirculation (EGR) system 304 back to the gas turbinesystem 204. As the exhaust gas 210 expands through an expander of thegas turbine system 204, it generates mechanical power to drive the maincompressor of the gas turbine system 204 and the electrical generator212 through the shaft 214.

The EGR system 304 is fluidly coupled to the HRSG 218 to transport andprocess the partially cooled gas turbine exhaust gas 216 back to the gasturbine system 204. The EGR system 304 may include various components(not shown), an exhaust gas cooler such as a direct contact cooler orshell and tube heat exchanger or air-fin heat exchanger to reduce thetemperature of the exhaust gas to about 4-66 degrees Celsius (° C.), awater spray to remove dust or debris from the exhaust gas, and/or aninertial separator to remove water droplets and mist from the cooledrecycle exhaust gas in line 216. The EGR system 304 may also include ablower, fan, or compressor to increase the pressure of the recycleexhaust gas by about 1-21 kPa. The blower, fan, or compressor cancompress and increase the overall density of the recycle exhaust gas,thereby directing a pressurized or compressed recycle exhaust gas inline 216 into the main compressor of the gas turbine system 204. Thepressurized recycle exhaust gas can be used to help facilitate astoichiometric or substantially stoichiometric combustion of the oxidant208 and fuel 206 by moderating the temperature of the combustionproducts.

The HRSG 218 of the cogeneration facility 302 generates and delivers thefirst stream of steam 220 to the steam turbine 222 to generateadditional mechanical power. The additional mechanical power can be usedto power a separate electrical generator. Alternatively, the steamturbine 222 can be coupled, for example, through a gear box, to theshaft 214 of the gas turbine system 204 to supplement the mechanicalenergy generated by the gas turbine system 204. Other systems may bedriven by the mechanical power, such as pumps, compressors, and/or otherfacilities.

The HRSG 222 also generates and delivers the second stream of steam online 224 to a thermal recovery system 226 to facilitate recovery ofviscous hydrocarbons from a reservoir. The thermal recovery system 226may implement a SAGD process, a steam-flooding process, a CSS process, aCHWE process, or the like.

In some embodiments, the first stream of steam 220 is high qualitysteam, and the second stream of steam 224 is low quality steam. Inaddition or alternatively, the cogeneration facility 302 may deliver thesecond stream of steam 224, or a third stream of steam, to a system thatuses the stream of steam in a utility heating process, a process heatingprocess, and/or a steam stripping process.

A water return system 306 provides at least a portion 308 of the feedwater used in the HRSG 218. The water return system 306 receives water310 produced from the thermal recovery system 226. The water 310produced by the thermal recovery system 226 may first be separated fromother well fluids before being sent to the water return system 306. Thewater return system 306 may process received water by filtration,stripping, pH control and/or other means so that it is suitable for useas feed water to the HRSG 218.

Another source of water to the water return system 306 is water producedby the combustion of fuel and oxidant within the gas turbine system 204.At least some water in the recycle exhaust gas 216 is condensed as therecycle exhaust gas is cooled. This condensed water 312 may betransported to the water return system 306 for processing and used tomake-up an imbalance between the flow rates of the steam 224 and theproduced water 310. In some cases, the condensed water 312 may exceedthe amount used for make-up, and some water may be exported or stored asindicated by an arrow 314. In other cases, the condensed water 312 maybe inadequate and additional water from storage or external supplies maybe received to make-up the stream of steam to the thermal recoverysystem 226 as indicated by the arrow 314.

The water return system 306 may also include a water purification systemfor preparing the portion 308 of water used as the make-up water to theHRSG 218. The water purification system can use any number of systemsknown in the art to filter the water, adjust the pH of the water,removed dissolved gases, remove dissolved oxygen, or remove dissolvedsolids. Such techniques can include, for example, hot lime softeningwhich may lower the concentration of contaminates by forcing theirprecipitation. Any number of other techniques may also be used alone orin various combinations, including filtration, steam stripping,evaporative purification (distillation), membrane purification, chemicalpurification, ion exchange, and the like. For example, the condensedwater 312 from the exhaust gas recirculation system 304 and HRSG 218will generally be at a low pH, e.g., about 4 pH units, as a result ofdissolved CO₂ in the exhaust. The low pH may cause damage to the HRSG218 as the steam is formed. To decrease this problem, a steam strippermay be used to remove the dissolved CO₂ and shift the pH to a higherlevel. Steam stripping may also be used, alone, or in combinations withoxygen scavengers, to remove oxygen from the portion 308 of the feedwater used in the HRSG 218 to lower the amount of oxygen injected by thethermal recovery process 226. Further, chemicals, such as sodiumsulfate, sodium carbonate, or others, can be added to increase the pH tobetween about 7 to about 9 pH units.

Water 310 produced from the thermal recovery process 226 may havesuspended or dissolved solids, or both, from the formation. Suspendedsolids may be removed by passing the water 310 through a filtrationsystem, for example, including fiber or ceramic filter cartridges, amongothers. Dissolved solids can be removed by reverse osmosis, among otherknown techniques. In an embodiment, the dissolved solids are notremoved, but allowed to pass through a low quality steam generator.Generation of low quality steam, e.g., 70% to 90% steam, is less likelyto cause fouling of a steam generator from dissolved solids.

Generally, since the wet CSS steam is not superheated and generally hasa steam quality in the range of 70 to 100%, the requirements for the CSSfeed water quality are not as stringent as those for the feed water thatis returned to or used as make-up to the steam turbine generationsystem.

The HRSG 218 may include two steam generation systems, a first one forthe stream of steam 220 for the steam turbine 222, and a second one forthe stream of steam 224 for the thermal recovery system 226. The firststeam generation system can use high quality boiler feed water toproduce high pressure, highly superheated steam for the steam turbine222 while, in some embodiments, the thermal recovery system 226 provideswet steam and, therefore, requires lower quality boiler feed water thatis consistent with re-use of water produced from the hydrocarbonreservoir with less extensive water treatment than would be required forthe steam turbine 222. Accordingly, the water return system 306 mayprocess and produce water of a first quality as feed water for the firststeam generation system of the HRSG 218 and water of a second quality asfeed water for the second steam generation system of the HRSG 218.

In addition, the steam turbine 222 generally requires less steam blowdown and therefore less water makeup, while certain thermal recoverysystems, such as a CSS system, effectively have a large continuous blowdown (i.e., wet steam is generally produced) and require more watermake-up to replace water that is not recovered from the hydrocarbonreservoir. Therefore, the HRSG 218 may receive the steam blowdown 316from the steam turbine 222 and use the steam blowdown 316 as make-upfeed water for the thermal recovery system 226. Using the steam blowdown316 as make-up feed water is a better alternative to the conventionalpractice of disposal, which is wasteful and which can have harmfuleffects on the environment.

The gas turbine system 204 may be adapted to extract a purge stream 318from the recycle exhaust gas 216. Moreover, the EGR system 304 may beadapted to extract a part of the recycle exhaust gas 222 as a productgas or alternate purge stream 320 prior to delivery of the recycleexhaust gas 216 back to the gas turbine system 204. The purge stream 318from the gas turbine system 204 and/or the alternate purge stream 320from the EGR system 304 are fluidly coupled to a gas separation system322. The gas separation system 322 may optionally include a catalyticsystem similar in purpose to the system described in the HRSG 218 tofurther remove products of incomplete combustion remaining in the purgestream 318 and/or alternate purge stream 320.

The gas separation system 322 may receive the purge stream 318 and/oralternate purge stream 320 and may employ any suitable gas separationtechnology to separate CO₂ from an inert gas in the extraction stream318 and 320. Suitable gas separation technologies include, but are notlimited to, solvent extraction using amines, hot potassium carbonate, orother solvents, molecular sieve separation, and solid sorbentseparation. The products of the gas separation system 322 are a CO₂ richstream 324 and a CO₂ lean stream 326. In some embodiments, the CO₂ leanstream 326 mainly consists of inert gases, such as nitrogen. Theseseparated streams may be used separately, in conjunction with eachother, or in conjunction with other production well fluids (e.g.,natural gas), to enhance a hydrocarbon thermal recovery process carriedout in the reservoir 106 or another proximate hydrocarbon reservoir.Proximate reservoirs may be those local to the viscous hydrocarbonreservoir 106 or those within an economic transport distance by pipelineor other transport methods.

For example, the CO₂ rich stream 324 may be fed to a reservoir miscibleflood process 328 for combined injection with steam, e.g., the stream ofsteam in line 224, into a reservoir. Injection of CO₂ with steamstimulation may increase recovery of viscous hydrocarbons relative tosteam stimulation alone. Alternatively, the CO₂ rich stream 324 can beused for sales, used in another processes requiring CO₂, and/or furthercompressed and injected into a terrestrial reservoir for sequestrationor another purpose. The CO₂ lean stream 326 may be fed to a reservoirpressure maintenance system 330 for maintenance of pressure levels inthe reservoir 106 or another proximate hydrocarbon reservoir.

The gas separation system 322 may separate anywhere from zero to 100% ofthe CO₂ from the purge extraction or alternate purge extraction streams.The separation percentage may be established by the separationtechnology employed or by the quantity of CO₂ or inert gas required in aspecific application. In some applications, only inert gases may berequired, and no CO₂ separation technology may be employed within thegas separation system 322. Further, the gas separation system 322 mayoperate at a low pressure similar to that of the alternate purge stream320 and may include compressors to increase the pressure of the CO₂ richstream 324 and/or the CO₂ lean stream 326. Alternatively, the gasseparation system 322 may operate at a high pressure similar to that ofthe purge stream 318 to reduce the size of the CO₂ separation equipmentand include additional compression as required for the product streams.The gas separation system 322 may also operate at higher pressures thaneither purge stream 318 or 320 by compressing the purge stream 318 or320 to reduce the size of the CO₂ separation equipment and reduce oreliminate the need for additional compression of the product streams 324and 326. Some CO₂ separation processes, such as hot potassium carbonate(Hot Pot), are only economical at higher pressures and, therefore, lowpressure extraction without compression would not be feasible for theseprocesses. In addition, either purge stream 318 or 320 may be injectedinto a subterranean reservoir, after any required compression andtreating, for enhanced hydrocarbon recovery, pressure maintenance,carbon sequestration or similar methods without separation into CO₂ richand CO₂ lean streams by a gas separation system 322. Stream 318, 320,324 or 326 may require further processing prior to injection into areservoir, such as dehydration or removal of contaminants by filtration,catalytic conversion or similar processes.

In some embodiments, the cogeneration facility 302 includes a controlsystem or systems (not shown) adapted to control the flow rate at whichfuel 206 and oxidant 208 are fed to the combustion chamber of the gasturbine system 204 to cause a near stoichiometric ratio of fuel andoxidant such that the equivalence ratio of the combustion is maintainedin the range of 0.8 to 1.2, 0.9 to 1.1, 0.95 to 1.05, or preferably 0.99to 1.02, while also achieving desired shaft power, temperature,pressure, flow or similar objectives. The control system or systems mayalso control the flow rate of the purge streams 318 and/or 320 tomaintain a flow or pressure or similar balance within the gas turbinesystem 204, the heat recovery steam generator 218, and the EGR system304.

The block diagram of FIG. 3 is not intended to indicate that thedevelopment 300 is to include all the components shown in FIG. 3.Further, the development 300 may include any number of additionalcomponents not shown in FIG. 3, depending on the details of the specificimplementation. For example, the development 300 may include any numberof additional valves, gear boxes, sensors, control systems, condensers,or the like.

FIG. 4 is a simplified block diagram of a portion 400 of the development300 illustrating an exemplary HRSG 218. Like numbered items are asdescribed with respect to previous figures. In the portion 400 shown,the HRSG 218 produces a stream of high quality steam in line 220, foruse by the steam turbine 222, and a stream of low quality steam in line224, for use by the thermal recovery system 226. Correspondingly, thewater return system 306 processes water to produce two streams of feedwater. The first feed water stream 402 is of a low quality relative tothe second feed water stream 404. Two steam generators 406 and 408 inthe HRSG 218 receive the respective feed water streams and generate thetwo streams of steam in lines 224 and 220, respectively. The steamgenerator 406 also receives the steam blowdown 316 from the steamturbine 228 as another source of feed water.

A controller (not shown) controls an amount of steam generated by eachsteam generator 406 and 408. For example, if a power demand is greaterthan a demand for hydrocarbon recovery, the controller opens and closesappropriate valves to direct a majority of the heat from the exhaust gasin line 216 to the steam generator 408, which generates steam for thesteam turbine 222. Conversely, if the exhaust heat is of greatereconomical use in recovering hydrocarbons, a majority of the heat isdirected to the steam generator 406, which generates steam for thethermal recovery system 226. Alternately, similar outcomes may beachieved by controlling the steam drum pressure for steam stream 220(preferred) or the steam drum pressure for steam stream 224 in a singleHRSG without the need to control the exhaust flow among the HRSGs. Byincreasing the pressure in a steam drum, the temperature at which thesteam boils is increased and less heat is transferred in the associatedsteam coils and less steam is produced in that coil. Consequently, moreheat remains in the exhaust flow to produce more steam in the othersteam coil. Thus by controlling the steam flow from the steam drums andaffecting the pressure in each stream drum, the amount of steam producedin the dry vs. the wet steam systems may be controlled.

FIG. 5 is a simplified block diagram of a portion 500 of the development300 illustrating another exemplary configuration of the HRSG 218. Likenumbered items are as described with respect to previous figures. As inthe portion 400 shown in FIG. 4, in the portion 500 shown in FIG. 5, theHRSG 218 produces a stream of high quality steam 220, for use by thesteam turbine 222, and a stream of low quality steam 224, for use by thethermal recovery system 226. However, in this example, the water returnsystem 306 processes water to produce a single stream of high qualityfeed water 308. The two steam generators 406 and 408 in the HRSG 218receive the feed water stream 308 and generate the two streams of steam224 and 220, respectively. To improve the quality of the stream of steamin line 220, a separator 502 in the HRSG 218 receives steam from thehigh quality steam generator 408 and separates a vapor phase or drysteam from a liquid phase or condensate. The dry steam leaves theseparator 502 via line 220 for use by the steam turbine 222.

At least a portion of the condensate from the separator 502 can berecycled to an inlet of the low quality steam generator 406. Typically,less than 100% of the condensate will be recycled, as any dissolvedsalts in the condensate will be concentrated over time and can foul theboiler tubes in the steam generator 406. Therefore, when recycling thecondensate, at least a portion is continuously purged to a disposal (notshown) and replaced by clean boiler feed water from the water returnsystem 306.

A controller (not shown) can control various elements of the HRSG 224including a set of valves 504. The valves 504 can be used to control theflow of steam and condensate to and from the separator 502 to vary theamounts of steam flowing through each of lines 220 and 224 and theamount of condensate flowing as feed water to the low quality steamgenerator 406.

Although the embodiments of the HRSG 218 shown in FIGS. 4 and 5implement two steam generators, other numbers of steam generators can beused, and additional streams of steam can be produced. For example, asingle steam generator may be used with a single separator to generate asingle stream of high quality steam. If low quality steam is desired insuch a configuration, a valve can be selectively opened or shut tobypass the separator. Furthermore, more than two steam generators can beused in the HRSG 218. Example embodiments of an HRSG 218 having multiplesteam generators are described, for example, in International PatentApplication No. WO/2012-170114 entitled, “Methods and Systems forProviding Steam,” published on Dec. 13, 2012, and incorporated herein byreference in its entirety. Moreover, the controller of the HRSG 218 cancontrol the HRSG 218 to produce high quality steam in both steam streams220 and 224 if, for example, a particular hydrocarbon thermal recoveryprocess calls for the use of high quality steam.

Methods for Using Exhaust Heat from Combined Cycle Plant for EnhancedOil Recovery

FIG. 6 is a process flow diagram of a method 600 for using exhaust heatin a combined cycle plant. The method begins at block 602, at whichexhaust heat from a gas turbine system in a combined cycle plant is usedto produce steam. At block 604, at least a first portion of the producedsteam is used in a hydrocarbon thermal recovery process. At block 606,at least a second portion of the produced steam is used to drive a steamturbine in the combined cycle plant.

At block 608, at least a third portion of the steam is used in anotherprocess such as a utility heating process, a process heating process,and/or a steam stripping process. Water produced as a byproduct of gascombustion in the gas turbine system is used as make-up feed water forproduction of the at least a first portion of the steam at block 610.Moreover, blowdown from the steam turbine is used as make-up feed waterfor production of the at least a first portion of the steam at block612.

The process flow diagram of FIG. 6 is not intended to indicate that allthe blocks of the method 600 shown in FIG. 6 are to be included in everycase. Further, any number of additional blocks not shown in FIG. 6 maybe included in the method 600, depending on the details of the specificimplementation.

FIG. 7 is a process flow diagram of another method 700 for using exhaustheat in a combined cycle plant. At block 702, high quality steam isproduced using exhaust heat from a gas turbine system in a combinedcycle plant. At block 704, low quality steam is also produced using theexhaust heat. An amount of the high quality steam produced relative toan amount of the low quality steam produced is adjusted at block 706.

At block 708, a steam turbine is driven using the high quality steamand, at block 710, the low quality steam is used in a thermal recoverysystem (e.g., by injecting the low quality steam into a reservoir tothermally recover viscous hydrocarbons in the reservoir), a Clark hotwater extraction system, a utility heating system, a process heatingsystem, and/or a steam stripping system. At block 712, blowdown from thesteam turbine is used as make-up feed water for the production of thelow quality steam. Water produced as a byproduct of gas combustion inthe gas turbine system is used as make-up feed water for the productionof the low quality steam at block 714.

The process flow diagram of FIG. 7 is not intended to indicate that allthe blocks of the method 700 shown in FIG. 7 are to be included in everycase. Further, any number of additional blocks not shown in FIG. 7 maybe included in the method 700, depending on the details of the specificimplementation.

Embodiments

Embodiments of the techniques may include any combinations of themethods and systems shown in the following numbered paragraphs. This isnot to be considered a complete listing of all possible embodiments, asany number of variations can be envisioned from the description herein.

-   1. A method for generating steam for hydrocarbon production using a    combined cycle power plant, including:

producing steam using heat from an exhaust stream from a gas turbinesystem;

condensing a water stream from combustion products in the exhauststream; and

using the water stream as a make-up water for production of the steam.

-   2. The method of paragraph 1, including:

chilling the exhaust stream to condense a second water stream;

combining the water stream and the second water stream to form acombined water stream; and

using the combined stream as the make-up water.

-   3. The method of paragraphs 1 or 2, including using at least a    portion of the steam to drive a steam turbine.-   4. The method of paragraph 3, wherein the steam turbine produces    additional shaft power on a shaft of the gas turbine system.-   5. The method of paragraphs 3 or 4, wherein the steam turbine    produces blowdown, and wherein the method includes using the    blowdown as make-up water for production of the steam.-   6. The method of any one of the preceding paragraphs, including    using at least a portion of the steam in a thermal recovery process    for hydrocarbons.-   7. The method of paragraph 6, wherein the thermal recovery process    is a cyclic steam stimulation process.-   8. The method of paragraphs 6 or 7, wherein the thermal recovery    process is a steam assisted gravity drainage process.-   9. The method of paragraphs 6, 7, or 8, wherein the thermal recovery    process is a Clark hot water extraction process.-   10. The method of any one of paragraphs 3-9, wherein the steam    turbine produces a blowdown stream, and wherein the method includes    using the blowdown stream as make-up feed water for production of    the steam used in a thermal recovery process.-   11. The method of any one of the preceding paragraphs, including    using at least a portion of the steam in a utility heating process,    a process heating process, or a steam stripping process, or any    combinations thereof-   12. The method of any one of the preceding paragraphs, including    recirculating the exhaust stream to the combustors as a diluent.-   13. The method of paragraph 12, including extracting a portion of    the diluent to offset the amount of fuel and oxidant added.-   14. The method of paragraph 13, including separating the extracted    portion of diluent into a carbon dioxide rich stream and a carbon    dioxide lean stream.-   15. The method of paragraph 14, including injecting the carbon    dioxide rich stream into a hydrocarbon reservoir for enhanced oil    recovery.-   16. The method of paragraphs 14 or 15, including injecting the    carbon dioxide rich stream into a subterranean formation for carbon    sequestration.-   17. The method of paragraphs 14, 15, or 16, including injecting the    carbon dioxide lean stream into a hydrocarbon reservoir for pressure    maintenance.-   18. The method of any one of the preceding paragraphs, including    treating the water stream prior to using the water stream as the    make-up water.-   19. The method of paragraph 18, including adjusting the pH of the    water stream to between about 7 and about 9 pH units.-   20. The method of paragraphs 18 or 19, including steam stripping the    water stream to remove dissolved gases.-   21. The method of paragraphs 18, 19, or 20, including treating the    water stream with an oxygen scavenger.-   22. The method of any one of the preceding paragraphs, including    operating the gas turbine system using a substantially    stoichiometric combustion process.-   23. The method of any one of the preceding paragraphs, including    generating a high quality steam and a low quality steam.-   24. The method of paragraph 23, including using the high quality    steam to drive a steam turbine.-   25. The method of paragraph 23 or 24, comprising:

obtaining reproduced water from a hydrocarbon thermal recovery system;

treating the reproduced water; and

using the reproduced water to produce the high quality steam or the lowquality steam, or both.

-   26. The method of paragraphs 23, 24, or 25, including using the low    quality steam in a thermal recovery process.-   27. A method for using exhaust from a combined cycle plant in    hydrocarbon production, including:

producing steam using exhaust heat from an exhaust stream from a gasturbine system in the combined cycle plant;

condensing a water stream from the exhaust stream;

using the water stream as a make-up stream for the steam production;

driving a steam turbine with at least a portion of the steam; and

injecting at least another portion of the steam into a hydrocarbonreservoir for a thermal recovery process.

-   28. The method of paragraph 27, wherein the portion of steam driving    the steam turbine is adjusted based at least in part on a level of    output power demanded from the combined cycle plant.-   29. The method of paragraphs 27 or 28, wherein the thermal recovery    process is cyclic steam stimulation.-   30. The method of paragraph 27, 28, or 29, wherein the thermal    recovery process is steam assisted gravity drainage.-   31. The method of any one of paragraphs 27-30, including driving a    steam turbine with the steam.-   32. The method of paragraph 31, wherein the steam turbine produces    additional shaft power on a shaft of the gas turbine system.-   33. The method of paragraph 32, including:

producing a blowdown stream from the steam turbine; and

providing the blowdown stream as make-up feed water for the productionof the steam.

-   34. The method of any one of paragraphs 27-33, including using the    steam in a Clark hot water extraction system, a utility heating    system, a process heating system, or a steam stripping system, or    any combinations thereof-   35. A system for generating power and thermally recovering    hydrocarbons from a reservoir, including:

a gas turbine system configured to produce a hot exhaust stream as abyproduct of combustion;

a heat recovery steam generator (HRSG) configured to produce a steamstream using the hot exhaust stream, wherein the HRSG produces acondensate stream from the combustion products in the hot exhauststream; and

a feed system configured to use the condensate stream as at least partof a make-up water provided to the HRSG to generate the steam stream.

-   36. The system of paragraph 35, including a steam turbine configured    to use at least a portion of the steam stream to generate mechanical    power.-   37. The system of paragraphs 35 or 36, including an electrical    generator driven by the mechanical power.-   38. The system of paragraph 36, wherein the steam turbine produces    additional shaft power on a shaft of the gas turbine system.-   39. The system of any one of paragraphs 35-38, including a    hydrocarbon production system configured to use a portion of the    steam stream to thermally recover hydrocarbons from a reservoir.-   40. The system of paragraph 39, including a cyclic steam stimulation    system.-   41. The system of paragraphs 39 or 40, including a steam assisted    gravity drainage system.-   42. The system of paragraphs 39, 40, or 41, including a Clark hot    water extraction system.-   43. The system of paragraph 35, including a water purification    system for the condensate stream.-   44. The system of paragraph 43, including a steam stripper    configured to decrease dissolved gases in the condensate stream.-   45. The system of paragraphs 43 or 44, including a pH adjustment    system configured to bring the pH of the condensate stream to    between about 7 and about 9 pH units.-   46. The system of paragraphs 43, 44, or 45, including a filtration    system.

While the present techniques may be susceptible to various modificationsand alternative forms, the exemplary embodiments discussed above havebeen shown only by way of example. However, it should again beunderstood that the techniques is not intended to be limited to theparticular embodiments disclosed herein. Indeed, the present techniquesinclude all alternatives, modifications, and equivalents falling withinthe true spirit and scope of the appended claims.

What is claimed is:
 1. A method for generating steam for hydrocarbonproduction, comprising: substantially stoichiometrically combusting acompressed oxidant and a fuel in a combustion chamber in a gas turbinesystem in the combined cycle power plant, thereby generating an exhauststream containing combustion products; producing steam using heat fromthe exhaust stream; injecting at least a portion of the steam into ahydrocarbon reservoir; obtaining hydrocarbons and reproduced water fromthe hydrocarbon reservoir using a thermal recovery process; condensing awater stream from the combustion products in the exhaust stream; andusing the water stream and at least a portion of the reproduced water asa make-up water for production of the steam.
 2. The method of claim 1,comprising: recirculating at least a portion of the exhaust stream tothe combustion chamber as a diluent for combustion; chilling the diluentprior to introduction into the combustion chamber to condense a secondwater stream; combining the water stream and the second water stream toform a combined water stream; and using the combined stream and the atleast a portion of the reproduced water as the make-up water.
 3. Themethod of claim 2, comprising extracting a portion of the diluent tooffset the amount of fuel and oxidant added.
 4. The method of claim 3,comprising separating the extracted portion of diluent into a carbondioxide rich stream and a carbon dioxide lean stream.
 5. The method ofclaim 4, comprising injecting the carbon dioxide rich stream into ahydrocarbon reservoir for enhanced oil recovery.
 6. The method of claim4, comprising injecting the carbon dioxide rich stream into asubterranean formation for carbon sequestration.
 7. The method of claim4, comprising injecting the carbon dioxide lean stream into ahydrocarbon reservoir for pressure maintenance.
 8. The method of claim1, comprising using at least a second portion of the steam to drive asteam turbine.
 9. The method of claim 8, wherein the steam turbineproduces additional shaft power on a shaft of the gas turbine system.10. The method of claim 8, wherein the steam turbine produces blowdown,and wherein the method comprises using the blowdown as additionalmake-up water for production of the steam.
 11. The method of claim 1,wherein the thermal recovery process is a cyclic steam stimulationprocess.
 12. The method of claim 1, wherein the thermal recovery processis a steam assisted gravity drainage process.
 13. The method of claim 1,wherein the thermal recovery process is a Clark hot water extractionprocess.
 14. The method of claim 1, comprising using at least a portionof the steam in a utility heating process, a process heating process, ora steam stripping process, or any combinations thereof.
 15. The methodof claim 1, comprising treating the water stream prior to using thewater stream as part of the make-up water.
 16. The method of claim 15,comprising adjusting the pH of the water stream to between about 7 andabout 9 pH units.
 17. The method of claim 15, comprising steam strippingthe water stream to remove dissolved gases.
 18. The method of claim 15,comprising treating the water stream with an oxygen scavenger.
 19. Themethod of claim 1, comprising generating a high quality steam comprising90 wt % or more water vapor and a low quality steam comprising less than90 wt % water vapor.
 20. The method of claim 19, comprising using thehigh quality steam to drive a steam turbine.
 21. The method of claim 19,comprising: treating the reproduced water.
 22. The method of claim 19,comprising using the low quality steam in the thermal recovery process.23. A method for using exhaust from a combined cycle plant inhydrocarbon production, comprising: substantially stoichiometricallycombusting a fuel and an oxidant in a gas turbine system in the combinedcycle plant to produce an exhaust stream; producing steam using exhaustheat from the exhaust stream; injecting at least a portion of the steaminto a hydrocarbon reservoir; obtaining hydrocarbons and reproducedwater from the hydrocarbon reservoir using a thermal recovery process;condensing a water stream from the exhaust stream; using the waterstream and at least a portion of the reproduced water as a make-upstream for the steam production; and driving a steam turbine with atleast a second portion of the steam.
 24. The method of claim 23, whereinthe portion of steam driving the steam turbine is adjusted based atleast in part on a level of output power demanded from the combinedcycle plant.
 25. The method of claim 23, wherein the thermal recoveryprocess is cyclic steam stimulation.
 26. The method of claim 23, whereinthe thermal recovery process is steam assisted gravity drainage.
 27. Themethod of claim 23, comprising: producing a blowdown stream from thesteam turbine; and providing the blowdown stream as additional make-upfeed water for the production of the steam.
 28. The method of claim 23,comprising using the steam in a Clark hot water extraction system, autility heating system, a process heating system, or a steam strippingsystem, or any combinations thereof.
 29. A system for generating powerand thermally recovering hydrocarbons from a reservoir, comprising: agas turbine system configured to produce a hot exhaust stream as abyproduct of substantially stoichiometric combustion of a compressedoxidant and a fuel; a heat recovery steam generator (HRSG) configured toproduce a steam stream using the hot exhaust stream, wherein the HRSGdelivers at least a portion of the steam stream to the thermal recoverysystem and produces a condensate stream from the combustion products inthe hot exhaust stream; a hydrocarbon thermal recovery system configuredto use at least a portion of the steam stream in a thermal recoveryprocess and produce hydrocarbons and reproduced water; and a feed systemconfigured to use the condensate stream and at least a portion of thereproduced water as make-up water provided to the HRSG to generate thesteam stream.
 30. The system of claim 29, comprising at least one of:(a) a steam turbine configured to use at least a second portion of thesteam stream to generate mechanical power cyclic steam stimulationsystem, wherein the steam turbine produces additional shaft power on ashaft of the gas turbine system; (b) an electrical generator driven bythe mechanical power; (c) a steam assisted gravity drainage system; (d)a Clark hot water extraction system; (e) a water purification system forthe condensate stream; (f) a steam stripper configured to decreasedissolved gases in the condensate stream; (g) a pH adjustment systemconfigured to bring the pH of the condensate stream to between about 7and about 9 pH units; and (h) a filtration system.